vreg beleidsplatform ‘slimme netten
TRANSCRIPT
FLEXIBILITY
VREG Beleidsplatform ‘Slimme
netten'
June 30, 2014 1
MEMBERS
June 30, 2014 2
CHALLENGES
FLEXIBILITY
June 30, 2014 3
GROWING NEED FOR FLEXIBILITY
June 30, 2014 4
Controlled by BRP via nominations
Balancing
Responsible
Party (BRP)
Import Export
Market
ConsumptionProduction
Forecasting
Forecasting
Dispatchable
Centralized
Dispatchable
Predictable
PRODUCTION
More de-centralized
Less dispatchable
Less predictable
BEFORE
NOW
Inelastic demand
CONSUMPTION
More elastic
demand
Flow of
flexibility
Flow of flexibility
Flow of flexibility
=
NEED TO INTEGRATE AGGREGATOR
• European Commission, Regulators and System Operators strongly support the development of demand response aggregation– E.g. Directive 2012/27/EU: Member States shall promote demand response
participation in spot and balancing markets
• Aggregators are already entering the market, but without a clear market model– Different market designs in different countries in Europe
• Issues arise when independent aggregators (= third parties) affect the existing business position of other market participants without proper compensation or settlement
June 30, 2014 5
How can the independent aggregator be integrated in the
market while limiting impact on existing market parties?
CENTRAL ROLE BRP
6
Source: Elia
June 30, 2014
BRP uses and valorises flexibility in his sourcing – in all timeframes
– in order to balance his portfolio.
Due to the increasing share of intermittent RES the BRP tasks
becomes more and more challenging!
ENFORCING ROLE BRP
• BRP should not have any negative financial impact due to an imbalance caused by anintervention of a third party
• Third parties are responsible for their own actions: a BRP cannot be held responsible for actions of third parties which he did not want and which he cannot controle
• BRP should be properly and timely informed to beable to fulfill its tasks
June 30, 2014 7
Every unilateral action of a third party (aggregator,
SO, …) in the perimeter of the BRP creates an
imbalance for the BRP, e.g. flexible access, load
shifting by SO, R3 ‘Dynamic Profile, …
TOWARDS A NEW MARKET DESIGN
FLEXIBILITY
June 30, 2014 8
BALANCE BETWEEN PRINCIPLES
June 30, 2014 9
Liberalized
market (market
based and tailor
made solutions,
….)
Cost efficiency (no
over-regulation,
limited
administrative
burden, …)
Fair split of
value and
risks
Right of
property Freedom of
enterprise and
contracting
Level playing
field between
market
parties
Market
integrity
Confidentiality
Sustainability
(future proof and
upscalable
solutions)
Transparency
and information
needs of market
parties
Presumption
of innocence
Avoiding market
abuse (risk of
BRP blocking
flexibility)
Consumer
protection
A GOOD MARKET DESIGN …
June 30, 2014 10
• Coherent market design for different markets
• Keep flexibility available for both market parties as well as system operators
… shall work in congestion, spot and balancing markets
• Additional information flows and operational tasks require room for proper pricing by existing market parties
• No seepage of additional costs form demand flexibility aggregator presence to existing markets, e.g. activation by third parties of flexibility services shall not increase balancing settlement prices
… shall put no additional costs on third parties without proper neutralization
• Aggregator flexibility is not only sourced from the customer, but also from its BRP (balance perimeter)
• The impact on the BRP is not limited to the activation window, e.g. rebound, load shifting, ramp up, …
… shall value flexibility correctly
• Current market models are created ad-hoc and based on a limited number of customers/aggregators
• Large-scale-roll-out requires operational processes and contracts that can be automated or standardized
… should be scalable
FEBEG envisages a robust market design in which costs and benefits are
allocated correctly!
RAMP UP
IMPACT ACTIVATION FLEXIBILITY
June 30, 2014 11
Pmax
Activation period
REBOUND
t
Diverted energy
Supply flexibility
SINGLE BRP VERSUS MULTIPLE BRP/TSO
June 30, 2014 12
Diverted
energy
BRP Source
BRP Requestor
BR
P 1
BR
P 1
BRP Source
BR
P 2
/TS
O
BRP Requestor/TSO
SIN
GLE
BR
PM
ULT
I B
RP
MW/h or MWh
MWh
Source-BRP with available flexibility = requestor BRP
Source-BRP with available flexibility Unbalanced requestor
• Necessary to transfer diverted energy fromSource-BRP toRequestor-BRP
• Transfer of divertedenergy impliesdetermination of volume and price
CONGESTION MANAGEMENT ON
DSO LEVEL
FLEXIBILITY
June 30, 2014 13
TYPES OF CONGESTION MANAGEMENT
May 12, 2014 14
• High risk of congestion in the grid or gridis congested
• SO intervenes by curtailing generation or load
Curtailmentof generation
or load
• Grid is not congested
• FSP wants to activate flexibility to offer tothird party (BRP, SO, …)
• SO limits flexibility activations to preventcongestion
Controlling of flexibility
activations
CURTAILMENT OF GENERATION
FLEXIBILITY
June 30, 2014 15
BALANCE OF SYSTEM IS KEY
• FEBEG congestion management model is based
on neutralizing impact on balancing market
(‘redispatch’)
• Inspired by Elia congestion rules in ‘CIPU’:
– Outcome of learning curve
– EU supported system
– Respects the BRP-balancing obligation
June 30, 2014 16
Main goal: system balance is guaranteed
(on BRP portfolio level) at all times
GENERAL PROCESS
June 30, 2014 17
Distribution
Grid User
DSO
TSO
Compen-
sation Tool
BRPRetailer
DSO
FSP
BSP
Congestion bids = compensation bids
- 3 MW
- 3 MW
- 3 MW + 3 MW
+ 3 MW
BRP is balanced!
- 3 MW
- 3 MW+ 3 MW
+ 3 MW
+ 3 MW
+ 3 MW
CONGESTION BIDS = COMPENSATIONS BIDS
• Congestion bids: DSO adapts generation (=
curtailment) to deal with system constraints
�Connection agreement: technical flexibility imposed in
the connection agreement between GU and DSO
�Commercial agreement: flexibility services offered on a
voluntary basis to a DSO, e.g. generation down by GU
with firm capacity or consumption up
• Compensation bids: DSO activates a compensation
bid on the TSO Compensation Tool in order to
compensate for the impact of the curtailment
June 30, 2014 18
Transfer of energy via automatic correction of BRP
perimeter via TSO on request of DSO.
FINANCIAL FLOWS
June 30, 2014 19
Distribution
Grid User
DSO
TSO
Compen-
sation Tool
BRPRetailer
DSO
FSP
BSP- 3 MW
- 3 MW + 3 MW
+ 3 MW
- Curtailed volume is generated by other generator or compensated by load shedding
- Grid user will be paid by retailer/BRP for production as if no activation was done
- FSP pays variable running costs to DSO (fuel cost, CO2 costs, maintenance, … - green
certicate*)
- DSO pays TSO for compensation bid
- 3 MWContractual
settlement as
if no
activation
was done
Contractual settlement as if
no activation was done
DSO pays for
compensation
bid
GU/FSP pays DSO for congestion bid
* FEBEG is in favor of shift towards investment support
- 3 MW
- 3 MW
COMPENSATION BIDS
• Only TSO can compensate perimeter BRP
• Need of cooperation between DSO and TSO
• TSO Compensation Tool:
– To maximise liquidity, at least following means shouldbe available via TSO Compensation Tool:
�Bidladder: compensation bids should have a locational signal
� Skip bids to avoid congestion
� Select specific bids to compensate locally
�CIPU: compensation bids by units connected to the transmission grid
– Remuneration of compensation bid will generally becheaper than imbalance price (imbalance price is cap)
June 30, 2014 20
ADVANTAGES
• No impact on commodity/balancing market (perimeter BRP)
• Proposal integrates existing tools or tools underdevelopment, e.g. know-how of bidladder
• Proposal could strengthen - if future integration of redispatch tool in bidladder - the balancing market creatingliquidity
• Proprosal looks for most cost-efficient solution– Most favorable congestion bid (merit order)
– Cheapest compensation bid in whole system (merit order)
– DGO cost is limited to difference between both (net cost is incentive to invest)
• Extendable to other cases, e.g. generation up, load down and up
• Neutral for BRP, retailer and grid user
• Level playing field between grid users
June 30, 2014 21
PROCESS FREE BAND
June 30, 2014 22
Distribution
Grid User
DSO
TSO
Compen-
sation Tool
BRPRetailer
DSO
FSP
BSPContract @
reduced price
Contract @
reduced price
- No congestion bids and no payments towards DSO: free band is compensation issue!
- No counter-balancing by TSO initiated by DSO
- Loss of quality of generated energy resulting in a reduced contract price paid by BRP/retailer
to GU
- Free band could be integrated in FEBEG congestion management model (settlement
discrepancies, …): no additonal operational processes needed
- 3 MW
BRP is not balanced!
MACRO-ECONOMIC ASSESSMENT
• Option of free band is a political decision
• Need for macro-economic assessment showing ‘social welfare’ of introducing a free band, taking into account:
– Maximum integration and promotion of renewables while free band has an impact on the profitability of renewables projects
– Objective to incentivize to build renewables in non-congested zones, but what about incentive for DSO to invest in the grid
– Fair split of costs between involved parties
• Other prerequisites for introducing a free band:
– More transparency on congested zones
– Transparency on methodology for the determination of the free band
– Free band should be known upfront, i.e. before investment decision, and is thus only applicable on new connections
June 30, 2014 23
If free band would be considered, then only within restrictive,
transparent and non-discriminatory legal framework
LEGAL FRAMEWORK
• Only in congested zones (and thus not
everywhere)
• Only temporary pending grid investments (and
thus not permanently)
• General rule (in grid code) or negotiable on
individual basis (in connection agreement)?
• Interruptibility = fixed %? Peak, volume, time, …?
• …
June 30, 2014 24
Legal framework is necessary to guarantee
the incentive for DSO’s to invest in the grid!
CONTROLLING OF FLEXIBILITY
ACTIVATIONS
FLEXIBILITY
June 30, 2014 25
PRE-QUALIFICATION AS ENDURING
SOLUTION?
May 19, 2014 26
Pre-qualifi-cation
?
Gridplanning
Conges-tion
manage-ment
Connection agree-
ment
System Operat-
ions
Transparency?
Public debate?
Cost benefit
analysis?
Learning curve?
EVOLUTION TOWARDS …
• Interactive, more transparant and closer to real-time process:
– Consecutive process (forecast, day-ahead prevision, close to real time information, …)
– SO’s provide information about (risk of) congestions
– BSP’s/FSP’s provide information about availableflexibility and planned flexibility actions
• Process should eventually – after cost benefit analysis - evolve towards real-time congestionmanagement
May 19, 2014 27
SO manages the congestion by cancelling planned
flexibility actions or activating available flexibility
CONCLUSIONS
FLEXIBILITY
June 30, 2014 28
A GOOD MARKET DESIGN …
June 30, 2014 29
… shall work in congestion, spot and balancing markets
… shall put no additional costs on third parties without proper neutralization
… shall value flexibility correctly
… should be scalable
EXAMPLE OF (DES)ACTIVATION …
June 30, 2014 30
June 30, 2014 31
QUESTIONS
BACK UP SLIDES
FLEXIBILITY
June 30, 2014 32
MARKET PARAMETERS TO TAKE
INTO ACCOUNT
FLEXIBILITY
June 30, 2014 33
DIFFERENT LOAD TYPES
June 30, 2014 34
Demand side flexibility
Storable load(process and supply
decoupled)
Non-storable load
Shiftable Non - shiftable
Curtailable
load
Non curtaila-
ble load
Self ge-
nerating
clients
LOAD TYPE MAKES A DIFFERENCE
• Storable and shiftable load (rebound):– Activation of demand flexibility has impact
– Consumed energy remains more or less the same
– Complex and unpredictable – in volume and time - impact afteractivation window (ramp up + rebound)
• Curtailable load and self-generating clients (no rebound):– Activation of demand flexibility has impact
– Less energy consumed
– Less complex impact after activation (ramp up)
– Total impact is more correlated with the market requesting the activation
June 30, 2014 35
Difficult to predict the full impact
Impact is centralized around the activation window
DIFFERENT REMUNERATION TYPES
June 30, 2014 36
Demand side flexibility
Capacity based
Fixed remuneration
€/MW/h
� Buy service (option)
���� Call option
Activation based
Variable remuneration
€/MWh
� Buy commodity
���� Back-to-back transaction
Hybrid model
Fixed remuneration to
cover fixed costs
+
Variable remuneration
to cover activation
REMUNERATION TYPE DOES MATTER
• Capacity based– Assumptions about commodity and operational costs are fixed upfront
– Fixed remuneration takes into account assumptions on the numbersof activations and the time of activation
– Ideal for the grid user to recuperate investment costs to participate in demand flexibility
– Fixed cost is controllable for contractual parties
– Unclear activation price (pre-paid option)
• Activation based– Price available for each individual activation
– Price could therefore differ in time
– Allows a merit order approach optimizing the offers
– Fixed cost must be recuperated via activation (uncertainty for griduser)
June 30, 2014 37
Combination of both models (hybrid model) is possible
TOWARDS ENDURING MARKET MODEL …
• A ‘merit order mechanism’ allows costefficient activation but, therefore, an activation price is needed
• Integrating product groups to clusters, e.g. R3-products, by harmonising activation rules
• Volume and price of activated energy must be known for an activation based system
38
•Primaryreserves
•Secondaryreserves
•Uncontractedreserves (‘Free Bids’)
•Tertiaryreserves via Generationunits
•Tertiaryreserves via sheddablecustomers
•R3DP •Reserve contracts withneighbouringTSO
•Disconnectcustomers(forced)
Cap
BRP/TSO BSP/FSP Grid user
€/MWh€/MWh€/MW/h
Act/Cap Act Act/Cap Act/Cap Cap Act N/a
Pre-contracted
Reserves
Pre-contracted
ReservesBidladder Bidladder
June 30, 2014
Example R3 ‘Dynamic Profile’:
� No economic criterion that
will lead to the activation
of the cheapest pool/BSP
� Activation without in-
creasing marginal cost and
thus saturating imbalance
price
DIFFERENT ACTIVATION FORMS
June 30, 2014 39
Demand side flexibility
Volume based Price based
Static Dynamic
Coupled
- DAM
(before
clearing)
- CIM
-Balancing
market
Uncoupled
- DAM
(After
clearing)
- Own
developed
price signal
Caps &
floors
Direct load
control
ACTIVATION FORMS ARE IMPORTANT
• Volume based– Limited freedom for the end user because of steering by FSP
– Requested volume is known, also time of activation and de-activation
– Price formula is agreed upfront between concerned market parties
– Guarantee of volume could be useful for certain markets
• Price based– Full freedom to the end user to modify consumption because FSP is
only giving a price incentive
– Requested volume is not known, neither the time of activation and de-activation, but are probably predictable at an aggregated level (learning curve)
– Difficult to distinguish normal supply (normal client behavior) anddemand flexibility (response to price signal)
June 30, 2014 40
Price based activation is difficult for FSP and is mainly applied
by integrated aggregators/suppliers/BRP to influence load
DIFFERENT MARKETS
June 30, 2014 41
Demand side flexibility
Balancing
DA, ID Real
time
Reserve
-ICH
-R3 DP
-…
BRP BRP/BSP TSO
Con-
gestion
TSO /DSO
Portfolio
optimi-
zation
BRP
Ade-
quacy
TSO
MARKET DETERMINES ACTIVATION FORM
• Portfolio optimization– Both price (integrated FSP/supplier/BRP) as volume (integrated or third party) based
activation are possible
• Balancing DA/ID/real time– Both price based (integrated) as volume based activation (integrated or third party
FSP) are possible
• Balancing reserves– Asks for volume based activation to have a guarantee on the available volume
– Activation should pass via FSP/BSP
• Congestion– Volume based activation gives guarantee on volume impact (commodity)
– Activation (possibly through FSP) has impact on other parties in the value chain thatshould be neutralized to avoid impact on balancing market
• Adequacy– Asks for volume based activation to have a guarantee on the available volume
– Activation should pass via FSP/BSP and has impact on other parties in the valuechain that should be neutralized to avoid impact on balancing market
June 30, 2014 42
